Split flow process and apparatus

ABSTRACT

An acid gas removal plant includes an absorber that provides a rich solvent to two regenerators that independently generate a lean and a semi-lean solvent, wherein the semi-lean solvent is produced in one of the regenerators using heat and/or steam derived from the other regenerator. Further heat integration is particularly contemplated with power plants in which the power plant provides high-level heat to the acid gas removal plant and wherein the power plant receives low-level heat from the acid gas removal plant.

This application claims the benefit of U.S. provisional application withSer. No. 60/393,595, which was filed on Jul. 3, 2002, and of U.S.provisional application with Ser. No. 60/467,719, which was filed May 2,2003, both of which are incorporated herein by reference.

FIELD OF THE INVENTION

The field of the invention is gas processing, especially as it relatesto removal of acid gas components of various feed gases, andparticularly flue gases.

BACKGROUND OF THE INVENTION

Various configurations and methods are known in the art to remove acidgas from a process gas (e.g., various distillation-, adsorption- andabsorption processes), and among those regenerator-absorber systems arefrequently employed as a relatively robust and cost-efficient gaspurification system.

In a typical regenerator-absorber system, gas is contacted in anabsorber in a counter-current fashion and the acid gas (or other gaseouscomponent) is at least partially absorbed by a lean solvent to produce arich solvent and a purified process gas. The rich solvent is thentypically heated in a cross heat exchanger and subsequently stripped atlow pressure in a regenerator. The so stripped solvent (ie., leansolvent) is cooled in the cross heat exchanger to reduce the temperaturein the lean solvent before completing the loop back to the absorber.Thus, such regenerator-absorber systems typically allow continuousoperation at relatively low cost. However, in many circumstances theextent of the acid gas removal efficiency is not satisfactory, andespecially where the acid gas is carbon dioxide, stringent emissionstandards can often not be achieved with a standard regenerator-absorbersystem.

To overcome problems associated with carbon dioxide removal in suchsystems, the temperature in the regenerator may be increased. However,increased corrosivity and solvent degradation often limit the degree ofoptimization for this process. Alternatively, a split-flow absorptioncycle may be employed in which the bulk of the solvent is removed froman intermediate stage of the regenerator column and recycled to anintermediate stage of the absorber. A typical split-flow process isdescribed by Shoeld in U.S. Pat. No. 1,971,798. In this arrangement onlya small portion of the solvent is stripped to the lowest concentration,and a high vapor to liquid ratio for stripping is achieved in the bottomtrays of the regenerator, resulting in somewhat lower energy use atrelatively low outlet concentrations. However, the reduction in energyconsumption is relatively low due to thermodynamic inefficiencies instripping (mainly because of variations in the solvent composition as itcirculates within the split loop).

To circumvent at least some of the problems with the split loop process,various improvements have been made. For example, one improvement to thesplit-flow process is to more accurately control the concentration ofsolvents. To more accurately control the solvent concentrations, twomodifications are generally necessary. The first modification comprisesan intermediate reboiler, which may be installed to a main regeneratorto boil off water from the semi-lean solvent to adjust the concentrationof the semi-lean solvent stream to the concentration of the leansolvent. The second modification comprises a side-regenerator toregenerate condensate from the main regenerator. The condensate from themain regenerator is sent to the top section of the main regenerator,where it undergoes partial stripping, and is then further stripped to avery low concentration of dissolved gas in the side-regenerator, beforebeing returned to the bottom reboiler of the main regenerator.

Since only a relatively small portion of the total solvent (typically˜20%) is stripped to the ultra-low concentration, relatively low outletconcentrations with comparably low energy use may be achieved.Furthermore, when methyl diethanolamine (MDEA) is employed as a solventin the improved split-flow process, the liquid circulation can bereduced by about 20%. However, the modifications to improve energy useand lower solvent circulation generally require a substantialmodification in the configuration of the main regenerator, and theinstallation of a side-regenerator, both of which may result insubstantial costs and significant down-time of an existingabsorber-regenerator system.

Another improvement to the split-flow process is described by Camell etal. in U.S. Pat. No. 6,139,605. Here, two regenerator columns areutilized wherein a primary regenerator produces a semi-lean solvent andwherein a secondary regenerator produces an ultra-lean solvent. A smallportion of the purified process gas leaving the absorber is expanded toa lower pressure level thereby producing a cooled purified process gas.The heated ultra-lean solvent stream leaving the secondary regeneratoris cooled by the cooled purified process gas thereby producing a heatedpurified process gas, which is subsequently fed into the secondaryregenerator. The recycled gas is then recovered from the secondaryregenerator and fed back into the feed gas stream at the absorber.

The use of a heated process gas instead of a reboiled solvent at thesecondary regenerator advantageously lowers the partial pressure of thesolvent vapor in the secondary regenerator, and allows the secondaryregenerator to operate a lower temperature than the primary regeneratorcolumn. Operating the secondary regenerator at a reduced temperaturetypically results in a reduced corrosivity of the solvent, which in turnmay allow for the use of cheaper materials such as carbon steel in placeof the conventional stainless steel. Furthermore, a split-flow processusing vapor substitution may be combined with fixed-bed irreversibleabsorption technology, e.g. to remove H₂S and or COS from the recyclegas in a bed of solid sorbent, thereby ensuring a relatively long bedlife of the absorber. However, due to the use of recycle gas and the useof a secondary regenerator column, retrofitting of existingabsorber-regenerator combinations may be relatively expensive and timeconsuming.

Therefore, although various improvements to the basic configuration ofan absorber-regenerator process are known in the art, all or almost allof them suffer from one or more disadvantages. Therefore, there is aneed to provide improved configurations and methods for the removal of agaseous component from process gases.

SUMMARY OF THE INVENTION

The present invention is generally directed to configurations andmethods for acid gas removal from various feed gases, and especiallylow-pressure flue gases, wherein an absorber receives a lean and asemi-lean solvent stream, wherein each of the solvent streams is formedfrom a rich solvent by a first and second regenerator. In suchconfigurations, it is especially preferred that first and secondregenerators are heat-integrated, and additional heat integrationbetween certain configurations and a power plant are also contemplated.

In one aspect of the inventive subject matter, a plant includes anabsorber that removes an acid gas from a feed gas using a lean solventand a semi-lean solvent, thereby producing a semi-rich solvent and arich solvent. A first regenerator receives a first portion of the richsolvent, thereby producing the lean solvent and a first regeneratoroverhead, and a second regenerator receives a second portion of the richsolvent, thereby producing the semi-lean solvent and a secondregenerator overhead, wherein the second regenerator overhead and thesemi-lean solvent are substantially exclusively produced from the secondportion of the rich solvent.

In especially preferred configurations of such plants, the secondportion of the rich solvent is preheated in a heat exchanger against thelean solvent from the first regenerator, and/or the second regeneratorreceives steam from a component in the plant (e.g., flashed steamcondensate from a steam reboiler of the first regenerator). Furthermore,it should be especially appreciated that in most, if not all of thecontemplated configurations, the absorber will operate at a pressurethat is lower than the pressure of the first and/or second regenerator.Such arrangements are particularly useful where the feed gas is a fluegas with relatively low pressure (e.g., less than 30 psia), and/orsignificant oxygen content (e.g. between 0.25% (vol.) and 20% (vol.)) atmoderate carbon dioxide levels (e.g., between 0.25% (vol.) and 30%(vol.)).

Especially contemplated absorbers may include an intercooler that coolsat least one of the semi-lean solvent and the semi-rich solvent (or amixture thereof). With respect to heat integration of suitable acid gasremoval configurations, it is generally contemplated that all processesthat provide and/or receive heat energy may be operationally coupled tothe acid gas removal configuration. However, it is generally preferredthat the acid gas removal configuration may receive high-level heat froma power plant as well as the flue gas, and may further provide low levelheat to the power plant (e.g., from the lean solvent cooler, thesemi-lean solvent cooler, the regenerator condenser, and/or theintercooler).

Thus, viewed from another perspective, contemplated plants willpreferably include an absorber that removes an acid gas from alow-pressure flue gas using a lean solvent and a semi-lean solvent,wherein the lean solvent is produced by a first regenerator operating ata first pressure, the semi-lean solvent is produced by a secondregenerator operating at a second pressure, and wherein each of thefirst and second pressures are greater than a pressure of thelow-pressure flue gas.

Various objects, features, aspects and advantages of the presentinvention will become more apparent from the following detaileddescription of preferred embodiments of the invention, along with theaccompanying drawings in which like numerals represent like components.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 is a schematic representation of one exemplary configuration of agas processing plant according to the inventive subject matter.

FIG. 2 is a schematic representation of another exemplary improvedconfiguration of a gas processing plant according to the inventivesubject matter.

FIG. 3 is a schematic representation of one exemplary improvedconfiguration of a gas processing plant according to the inventivesubject matter.

FIG. 4A is a schematic representation of one exemplary configuration forheat integration of a gas processing plant according to the inventivesubject matter.

FIG. 4B is a schematic representation of another exemplary configurationfor heat integration of a gas processing plant according to theinventive subject matter.

DETAILED DESCRIPTION

The inventors discovered that configurations and methods in which a leansolvent and a semi-lean solvent are employed for removal of a gaseouscomponent (and especially an acid gas) from a feed gas can be operatedwith improved efficiency when the lean solvent and semi-lean solvent areproduced in separate regenerators. Unexpectedly, despite the increasedsolvent flow rate requirements of such configurations, the inventorsdiscovered that all or almost all of the contemplated configurationsprovide significant economic advantages that are predominantly due toreducing heating energy demand.

Moreover, the inventors discovered that various operational aspects ofcontemplated configurations may be even further improved when (a) thesemi-lean solvent regenerator is stripped with steam flashed fromcondensate produced in the lean regenerator reboiler, (b) an absorberintercooler is employed that maintains a lower solvent temperatureacross the absorber, and/or (c) where the heat energy in- and output isintegrated with another plant (e.g., power plant, reformer plant, etc.).

One exemplary configuration is depicted in FIG. 1 in which a plant 100in which a feed gas 102 enters the absorber 110 at feed gas pressure.Lean solvent 122 enters an upper portion of the absorber 110 andcontacts the feed gas within the absorber to form semi-rich solvent 124,which is fed to a lower portion of the absorber 110. The semi-richsolvent 124 may be mixed with the semi-lean solvent 132 to form a mixedsolvent (not shown). Alternatively, the semi-rich solvent 124 and thesemi-lean solvent 132 may also enter the lower portion of the absorberseparately. Furthermore, and depending on the particular configuration,semi-rich solvent 124, the semi-lean solvent 132, and/or the mixedsolvent may be cooled by an absorber intercooler 150. It should furtherbe recognized that multiple intercoolers may be used in conjunction withthe teachings presented herein, wherein each of the intercoolers maycool a side draw of the absorber. Therefore, and in this context,multiple semi-rich solvent streams may be cooled. Consequently, asemi-lean cooler as shown in FIGS. 1 and 2 may be omitted.

Rich solvent 106 will leave the absorber 110 at or near the bottom ofthe absorber, and the processed feed gas will leave the absorber 110 aslean gas 104. The rich solvent 106 is then split into a first and secondportion (106A and 106B, respectively), wherein both portions are heatedin a solvent cross exchanger 140 against the lean solvent from the firstregenerator 120 and the semi-lean solvent 132 from the secondregenerator 130. Of course, it should be recognized that wheredesirable, the rich solvent may be first heated in the cross exchanger(or other suitable heat source) before the rich solvent is divided intothe first and second portions.

The first regenerator 120 removes the gaseous component (e.g., acid gas)from the solvent 106A with heat provided by the steam reboiler 128.First regenerator overhead 126 is further cooled in regeneratorcondenser 160 and separated into condensate and acid gas in accumulator162. The lean solvent 122 from the first regenerator 120 isre-introduced into the absorber 110 after heat exchange in crossexchanger 140 (supra).

The second regenerator 130 removes from the second portion 106B at leastpart of the gaseous component to generate semi-lean solvent 132 andsecond regenerator overhead 136, which is then combined with the firstregenerator overhead 126. Stream 136 may also be washed in a top washsection of the first regenerator. It should be especially appreciatedthat the second portion of the rich solvent 106B is heated in the crossexchanger (e.g. against the lean solvent 122 and/or the semi-leansolvent 132) to promote regeneration of the semi-lean solvent withoutadditional expenditure of heat energy. Additionally, or alternatively,as depicted in FIG. 2, regeneration of the semi-lean solvent 232 in thesecond regenerator 230 may also be assisted by steam 276 that isgenerated within the gas treatment plant 200 (or elsewhere). Here, steam276 is derived from the steam reboiler 228 of the first regenerator 220,wherein the condensate 272 from reboiler 228 is flashed to the operatingpressure of the second regenerator, and separated in the flash drum 280into condensate flash liquid 274 and condensate flash steam 276 (withrespect to the remaining configuration, the same considerations as forFIG. 1 apply). It should be especially recognized that in suchconfigurations the steam will decrease the acid gas load in thesemi-lean solvent, which will in turn reduce the overall solventcirculation rate. Remarkably, no additional steam needs to be importedfrom a source outside of the plant as that steam is already available asa byproduct of the steam reboiler.

It is generally contemplated that the source, composition, and otherparameters of suitable feed gases may vary considerably, and theparticular composition, pressure, temperature, etc. will predominantlydepend on the particular source. However, especially preferred feedgases include flue gases from reformer burner or gas turbine exhausts.It should further be appreciated that gases other than flue gases from acombustion turbine are also contemplated, including natural gas, orvarious refinery gases, combustion gases, or combined gases frommultiple sources, all of which may or may not be pretreated(contemplated pretreatment may include fractionation, filtration,scrubbing, and combination or dilution with other gases). Thus, thechemical composition may vary substantially, but suitable feed gasespreferably have relatively low carbon dioxide (typically between 0.25and 30 vol %) and relatively high oxygen content (typically between 0.25and 20 vol %). Consequently, depending on the nature of the process gasand the physico-chemical properties of the solvent, the gaseous compoundis not necessarily limited to carbon dioxide, but may also includehydrogen sulfide, nitrogen, oxygen, hydrogen, and/or helium, etc.

It is further contemplated that the pressure of the feed gas istypically relatively low and will generally be in the range of between0.1 psia and 30 psia However, contemplated higher pressures includepressures of between about 30 psia and 150 psia, and less typicallybetween about than 150 psia and 300 psia. Similarly, the temperature ofcontemplated feed gases may vary and will predominantly depend on theparticular source and/or use of a heat recovery unit.

With respect to the absorber, it is contemplated that all conventionalabsorbers are considered suitable for use in conjunction with theteachings presented herein. For example, contemplated absorbers includerandom packed-bed absorbers with a capacity of up to 30 million standardcubic feet per hour (and even more), but may include various alternativetypes, sizes, and capacities. Among other variations, contemplatedabsorbers may include structured packed-bed absorbers or trayed-typeabsorbers. Similarly, where relatively large capacities of process gasare to be purified, multiple absorbers with same or different capacitymay be utilized. Contemplated feed gas capacities include flow rates ofbetween 1-50 million standard cubic feet per hour (MMSCF/hr), and evenhigher flow rates between 50 -100 MMSCF/hr are also contemplated. On theother hand, where smaller quantities of process gas are to be purified,flow rates of between 0.1-50 MMSCF/hr and less are also deemed suitable.

It should be particularly noted that in preferred aspects of theinventive subject matter the absorber operates at a pressure that issubstantially identical (+/− 5 psi) to the pressure of the feed gas(which may be directly provided to the absorber as exhaust with orwithout a blower). Therefore, suitable absorber pressures will typicallybe in the range of between about 5 psia to 25 psia, more typically inthe range of about 10 to 20 psia, and most typically in the range ofabout 14-17 psia. Alternatively, the absorber pressure may also exceed20 psia, and suitable pressures of up to 300 psia (and even higher) arenot excluded.

Similarly, it should be recognized that the first and secondregenerators may vary substantially in type and volume, and the type andvolume of suitable regenerators will depend at least in part on theabsorber and nature of the feed gas. Therefore, it is generallycontemplated that all conventional configurations are deemed suitablefor use in conjunction herein so long as a first and second regeneratorreceive a first and second portion of a rich solvent directly orindirectly from the absorber, respectively, and so long as the overheadand the semi-lean solvent of the second regenerator are substantiallyexclusively produced from the second portion of the rich solvent. Theterm “substantially exclusively produced from the second portion of therich solvent” as used herein means that the rich gaseous stream leavingthe top of the first regenerator is typically not (or if so, then nomore than 20 vol %) routed into the semi-lean solvent regenerator,and/or that the feed to the second regenerator comprises at least 80% ofthe second portion of the rich solvent. Optionally added stripping gasor steam (see e.g., FIG. 2) is not included in this definition.

Consequently, it should be especially recognized that the partialpressure of the acid gas component in any vapor feed in the secondregenerator remains relatively low. Furthermore, it should beappreciated that the second regenerator may be operated as a flash drumthat receives heated rich solvent and that may further receive steam toreduce the acid gas partial pressure above the solvent in the flashdrum.

With respect to suitable pressures in the first and second regenerators,it is generally contemplated that the pressure in at least one of thefirst and second regenerator is higher than in the absorber, and itshould be recognized that a particular pressure in the first and/orsecond regenerator will predominantly depend on the particular solventand solvent concentration, temperature, and/or (residual) carbon dioxideloading in the solvent. Thus, contemplated pressure differences betweenat least one of the regenerators and the absorber will be at least 2psi, more typically at least 5 psi, and most typically between 10-15psi. Furthermore, with respect to the amount of steam provided to thesecond regenerator, it should be recognized that the steam quantitiesmay vary considerably.

Likewise, the reboiler of the first regenerator is not restricted to asteam operated reboiler, but may also be alternative reboilers,including oil-heated, or flame heated, or electrically heated reboilers.Furthermore, it should be recognized that suitable pumps, valves, andpiping will be readily available to a person of ordinary skill in theart, and that their implementation into the configurations according tothe inventive subject matter will not require undue experimentation.

With respect to the solvent, it is generally preferred that the solventis an aqueous amine-containing solvent (chemical solvent), andparticularly preferred solvents include those comprisingmonoethanolamine (MEA). However, it should be recognized that numerousalternative solvents are also considered appropriate, including physicaland chemical solvents, and any reasonable combination thereof. Forexample, physical solvents include SELEXOL™ (a dimethyl ether ofpolyethylene glycol) and methanol, while chemical solvents includeorganic amines and mixed amines. Especially contemplated chemicalsolvents are MEA, diethanolamine, diglycolamine, andmethyldiethanolamine. It should further be appreciated that co-solventsin combination with contemplated solvent are also appropriate. Suitablesolvents are generally commercially available, or may be prepared tospecification for selected purposes. Furthermore, and especially wherethe feed gas comprises appreciable quantities of oxygen, contemplatedsolvents may additionally include corrosion inhibitors. There arenumerous corrosion inhibitors known in the art, and exemplary inhibitorsare described, for example, in U.S. Pat. Nos. 6,036,888, 4,596,849, or4,372,873. Still further suitable reagents that may be added or includedto contemplated solvents are anti-foam agents, buffers, metal salts,etc.

With respect to the heating of the rich solvent stream(s) and cooling ofthe lean solvent stream and/or semi-lean solvent stream, it iscontemplated that various devices other than a cross heat exchanger arealso appropriate. For example, the rich solvent stream may be heatedutilizing residual heat from the steam reboiler, or from heat sourcesother than a heat exchanger, including hot fluids, hot gases, andelectricity. Similarly, the cooling of the lean solvent stream andsemi-lean solvent stream may be performed with a single, or twoindependent cooling devices that employ water, air, or otherrefrigerants as coolants. The cooling devices may thereby beenergetically coupled or independent from the gas purification process.Although side coolers are preferably employed for such cooling, variousalternative configurations are also contemplated, including multipleside coolers or a single side cooler with two independent channels forthe two solvent streams. Still further, and especially where thesemi-rich solvent stream is mixed with the semi-lean solvent stream, theintercooler may be employed to cool the mixed solvent, and/or thesemi-rich and/or semi-lean solvent stream. Contemplated coolerspreferably reduce the temperature of the lean solvent stream and thesemi-lean solvent stream more than 10° C., more preferably more than 25°C., and most preferably more than 50° C. However, and especially wherean intercooler is employed, alternative reductions of temperature arealso considered suitable. Alternative cooling systems includecoil-cooled trays, or internal heat exchangers.

In still further alternative aspects of the inventive subject matter,the semi-rich solvent stream need not be limited to a single semi-richsolvent stream with a particular carbon dioxide loading (e.g., greaterthan 0.3), but may include multiple semi-rich solvent streams withidentical or different carbon dioxide loading, so long as at least partof the semi-rich solvent stream is fed back to a lower portion of theabsorber. For example, appropriate semi-rich solvent streams may bedrawn off the absorber at different positions that may or may not havethe same vertical distance from the top of the absorber. Furtherconfigurations and aspects relevant to contemplated configurations andmethods can be found in our commonly owned U.S. Pat. No. 6,645,446 whichis incorporated by reference herein.

In still further contemplated aspects of configurations and methodsaccording to the inventive subject matter, the low pressure steam 270for the reboiler may also be provided by a source other than the gastreatment plant, and especially suitable sources include heat recoveryunits of various plants (infra). Thus, and at least from one perspectiveas shown in FIG. 3, contemplated plant configurations include those inwhich a recovery plant (e.g., gas treatment plant for recovery of carbondioxide) is heat-integrated with a power plant, wherein low-level heatis provided by the recovery plant to the power plant, while high-levelheat is provided from the power plant to the recovery plant. Forexample, a recovery plant may provide heating for boiler feed water of apower plant from recovery plant heat sources that include solventcoolers (e.g., lean solvent cooler, semi-lean solvent cooler), orcondensers (e.g., regenerator condenser), while the power plant mayadvantageously provide heat to convert low pressure steam condensateinto low pressure steam that operates the steam reboiler of the firstregenerator in the recovery plant. The terms “gas treatment plant”, “gasprocessing plant” and “recovery plant” are used interchangeably hereinand refer to contemplated plants in which a gaseous component (typicallyacid gas, most typically carbon dioxide) is removed from a feed gas.

Still further preferred heat-integration schemes of contemplated plantsinclude those in which the heat energy demand for the recovery plant isat least in part, or even entirely provided by the source of the feedgas that is to be treated with the recovery plant. For example, FIG. 4Adepicts a configuration in which flue gas (e.g., from a reformer) isdirected through a heat recovery unit in which boiler feed water isconverted to low pressure steam that can be used to operate the firstregenerator of a plant having a configuration of FIG. 1. Where required,extra fuel may be used to raise the temperature in the heat recoveryunit (e.g., via duct firing). Alternatively, as shown in FIG. 4B, wherethe heat of the flue gas in the heat recovery unit is sufficiently high,power may be generated using high pressure steam that is generated inthe heat recovery unit. Resulting low pressure steam from the powergeneration may then be employed in the recovery unit to drive processesthat require heat energy (e.g., steam reboiler for first regenerator).Thus, it should be particularly recognized that where heretofore knownacid gas removal plants satisfied their heat demands with a separatesteam boiler (which in turn generated again acid gases in the boilerfurnace), contemplated configurations employ the heat content of the ofthe flue gas (or other heat source in the plant that generates the fluegas) to drive the heat-dependent process(es) in the recovery plant.

Such heat integration configurations are particularly advantageous wherethe flue gas contains oxygen in an amount sufficient to supportcombustion of additional fuel (typically oxygen concentration of 4%(vol.), or more). Therefore, especially suitable flue gases include gasturbine exhausts and reformer flue gases. In such configurations, a heatrecovery unit is positioned upstream of a flue gas treating unit(e.g.,desulfurization and/or carbon dioxide removal) in which ductfiring is performed via injection of natural gas or other fuel to theflue gas. The combustion of the natural gas or other fuel with theremaining oxygen of the flue gas increases the flue gas temperature tothe point that steam can be raised and sent to the reboiler of the firstregenerator of FIG. 1 or 2.

Among other advantages, it should be recognized that such processes aretypically superior to generation of steam from a boiler or extractionfrom a steam turbine, since (a) the flue gas is already hot, andconsequently the amount of natural gas or other fuel required is smallerthan the amount required in a boiler; (b) the flue gas becomes moreconcentrated in carbon dioxide, thereby significantly increasing theefficiency of carbon dioxide capture in the process; (c) the flue gasoxygen concentration is reduced, thus reducing the rates of aminedegradation in the acid gas removal process, (d) the hot temperaturereached after duct firing allows for the addition of a NO_(x) removalunit, (e) prevent new emissions of carbon dioxide from a separate boilerotherwise required to raise steam for the solvent regeneration, and (f)reduces overall cost.

To determine the economic benefit of an exemplary configuration usingcontemplated heat integration configurations, comparative simulationswere performed using a process resulting in the production of 413ton/day of carbon dioxide (see FIG. 4B). For comparison (case A), atypical reformer flue gas, containing 6.0% carbon dioxide at 302° F. wassent directly to a flue gas desulfurization and Econamine FG Plus(process substantially as depicted in FIGS. 1 and 2) processes. Incontrast (case B), the same flue gas was sent first through a heatrecovery unit which was heat integrated with the same flue gasdesulfurization and Econamine FGPlus process. The two cases werecompared at constant moles of carbon dioxide recovered and constantabsorber packing height. The Econamine FG Plus process was designed withsplit flow configuration, intercooled absorber, 35 wt % aqueous MEA assolvent, and with 15° F. minimum cross exchanger approach temperature.The heat recovery unit was designed with a minimum approach temperatureof 15° F. The temperature of the flue gas in the desulfurization/DCCunit was set to 104° F.

A B EFG Feed Gas CO₂ Concentration % v/v 6.0 7.2 EFG Feed Gas O₂Concentration % v/v 6.8 4.7 EFG Solvent Circulation Rate gpm 1,873 1,652EFG Specific Reboiler Duty Btu/lb C0₂ 1,597 1,487 Blower BHP hp 1,1541,316 Flue Gas Max Temperature ° F. 302 786 Flue Gas to TreatingTemperature ° F. 302 297

The flue gas carbon dioxide concentration increases from 6.0 to 7.2%,thus increasing the MEA solvent capacity. The same removal can beobtained with a lower circulation rate and the increased rich loadingmakes stripping easier. The result is a reduction of reboiler duty ofapproximately 6.9%. The blower power increases, due to the pressure dropthat the flue gas undergoes in the heat recovery unit (set to 10″ H₂O).

Alternatively, power may be generated by production of higher pressuresteam in the heat recovery unit (see FIG. 4B). The steam can besuperheated and expanded in a turbine and the extraction steam (50 psig,superheated) can be sent to the reboiler, while some power is producedto satisfy the demand of the Econamine FG Plus process. A third case (C)was run with the simulator to reproduce this configuration, with a steampressure of 450 psig. The Table below reports the results of thatsimulation, comparing the third case C to case B.

B C Steam Pressure psig 50 450 Mass of CH₄ required lbs/hr 2,385 3,044Flue Gas Max Temperature ° F. 786 911 Flue Gas to Treating Temperature °F. 297 372 EFG Feed Gas CO₂ Concentration % v/v 7.2 7.5 Blower BHP hp1,316 1,312 Expander Power Output hp N/A 2,847

As can be seen, by using approximately 30% more natural gas, 2,847 hpare produced (2.1 MW). This power completely satisfies the consumptionof the blower, which is by far the most power consuming unit in theprocess.

Therefore, the inventors generally contemplate a plant that includes anabsorber that removes an acid gas from a feed gas using a lean solventand a semi-lean solvent, thereby producing a semi-rich solvent and arich solvent. Such plants will further comprise a first regenerator thatreceives a first portion of the rich solvent, thereby producing the leansolvent and a first regenerator overhead, and a second regenerator thatreceives a second portion of the rich solvent, thereby producing thesemi-lean solvent and a second regenerator overhead, wherein the secondregenerator overhead and the semi-lean solvent are substantiallyexclusively produced from the second portion of the rich solvent.Preferably, the second portion of the rich solvent is preheated in aheat exchanger against the lean solvent from the first regenerator,and/or the second regenerator further receives steam from a component inthe plant (e.g., steam reboiler of the first regenerator; therefore, thesteam may be a flashed steam condensate from the steam reboiler).

In most, if not all of preferred aspects, the absorber (preferablyfurther comprising an intercooler cooling the semi-lean, semi-rich,and/or a mixed solvent) will operate at a pressure that is lower than anoperating pressure of the first regenerator and an operating pressure ofthe second regenerator. For example, a suitable feed gas entering theabsorber may be a flue gas at a pressure of no more than 20 psia (e.g.,the acid gas in the feed gas is carbon dioxide and has a concentrationof between 0.5% (vol.) and 3.5% (vol.) and wherein the feed gas furthercomprises oxygen at a concentration of between 5% (vol.) and 15%(vol.)).

Contemplated plants may further be heat integrated with other plants(e.g., ammonia gas production plants with a reformer, a power plant witha gas turbine, etc.) that may provide heat (typically high-level heartfor steam reboiler) and advantageously the feed gas, while the otherplant may also receive heat from contemplated plants (typically lowlevel heat to preheat boiler feed water). Thus, viewed from anotherperspective, contemplated plants will include an absorber that removesan acid gas from a low-pressure flue gas using a lean solvent and asemi-lean solvent, wherein the lean solvent is produced by a firstregenerator operating at a first pressure, the semi-lean solvent isproduced by a second regenerator operating at a second pressure, andwherein each of the first and second pressures are greater than apressure of the low-pressure flue gas.

Thus, specific embodiments and applications of improved split flowconfigurations and processes have been disclosed. It should be apparent,however, to those skilled in the art that many more modificationsbesides those already described are possible without departing from theinventive concepts herein. The inventive subject matter, therefore, isnot to be restricted except in the spirit of the appended claims.Moreover, in interpreting both the specification and the claims, allterms should be interpreted in the broadest possible manner consistentwith the context. In particular, the terms “comprises” and “comprising”should be interpreted as referring to elements, components, or steps ina non-exclusive manner, indicating that the referenced elements,components, or steps may be present, or utilized, or combined with otherelements, components, or steps that are not expressly referenced

1. A plant comprising: an absorber that is configured to remove an acidgas from a feed gas, wherein the absorber is further configured toreceive a lean solvent and a semi-lean solvent and to produce asemi-rich solvent and a rich solvent; a first regenerator fluidlycoupled to the absorber and configured to receive a first portion of therich solvent and further configured to produce the lean solvent and afirst regenerator overhead; a second regenerator fluidly coupled to theabsorber and configured to receive a second portion of the rich solventand further configured to produce the semi-lean solvent and a secondregenerator overhead; a heat exchanger operationally coupled to theabsorber and configured to preheat the second portion of the richsolvent against the lean solvent from the first regenerator; and whereinthe first and second regenerators are configured such that the secondregenerator overhead and the semi-lean solvent that is fed to theabsorber are substantially exclusively produced from the second portionof the rich solvent.
 2. The plant of claim 1 wherein the secondregenerator is further configured to receive steam from a component inthe plant.
 3. The plant of claim 2 wherein the component is a steamreboiler of the first regenerator and wherein the steam is a flashedsteam condensate from the steam reboiler.
 4. The plant of claim 1wherein the absorber is configured to operate at a pressure that islower than an operating pressure of the first regenerator and anoperating pressure of the second regenerator.
 5. The plant of claim 4wherein the feed gas comprises flue gas at a pressure of no more than 30psia.
 6. The plant of claim 5 wherein the acid gas in the feed gas iscarbon dioxide and has a concentration of between 0.25% (vol.) and 30%(vol.) and wherein the feed gas further comprises oxygen at aconcentration of between 0.25% (vol.) and 20% (vol.).
 7. The plant ofclaim 1 wherein the absorber is coupled to an intercooler that isconfigured to receive and cool at least a portion of the semi-richsolvent to thereby form a cooled semi-rich solvent.
 8. The plant ofclaim 7 further comprising fluid conduits that are configured to allowmixing of at least a portion of the semi-lean solvent with the semi-richsolvent to thereby form a mixed solvent, and wherein the intercooler isconfigured to cool the mixed solvent to form a cooled mixed solventsuitable for introduction into the absorber.
 9. The plant of claim 1wherein the absorber is coupled to an intercooler that is configured toreceive and cool at least a portion of the semi-lean solvent to therebyform a cooled semi-lean solvent suitable for introduction into theabsorber.
 10. The plant of claim 1, optionally comprising an intercoolerthat is operationally coupled to the absorber, and a power plant orreforming plant operationally coupled to the plant, wherein the powerplant or reforming plant is configured to provide energy for a reboilerof the first regenerator, and the absorber feed gas, and optionallywherein a heat recovery unit that employs duct firing is configured toprovide the energy.
 11. The plant of claim 10 further comprising atleast one of a lean solvent cooler, a semi-lean solvent cooler, and aregenerator condenser, each configured to allow providing heat to thepower plant.
 12. The plant of claim 1, optionally comprising anintercooler that is operationally coupled to the absorber, furthercomprising at least one of a lean solvent cooler, a semi-lean solventcooler, and a regenerator condenser, wherein a power plant isoperationally coupled to the plant and wherein the power plant isconfigured to allow providing of heat to the power plant by at least oneof the lean solvent cooler, the semi-lean solvent cooler, theregenerator condenser, and the intercooler.
 13. A plant comprising: anabsorber that is configured to remove an acid gas from a low-pressureflue gas and further configured to receive a lean solvent and asemi-lean solvent, a first regenerator configured to operate at a firstpressure and to produce the lean solvent, a second regeneratorconfigured to operate at a second pressure and to produce the semi-leansolvent wherein the absorber is further configured such that the leansolvent and the semi-lean solvent are fed to the absorber, and such thateach of the first and second pressures are greater than a pressure ofthe low-pressure flue gas.
 14. The plant of claim 13 wherein the firstand second regenerators are configured to receive a first and secondportion of a rich solvent, respectively, and wherein the absorber isfurther configured to produce the rich solvent.
 15. The plant of claim14 wherein the second portion of the rich solvent is heated by the leansolvent of the first regenerator before the second portion of the richsolvent enters the second regenerator.
 16. The plant of claim 13 whereinthe second regenerator is further configured to receive steam flashedfrom condensate of a steam reboiler of the first regenerator.
 17. Theplant of claim 13 wherein the absorber is coupled to an intercooler, andwherein the intercooler is configured to cool at least one of asemi-rich solvent produced by the absorber and the semi-lean solventproduced by the second regenerator.
 18. The plant of claim 13 whereinthe low pressure flue gas comprises no more than 30%(vol.) carbondioxide and less than 20%(vol.) oxygen, and wherein the low pressureflue gas has a pressure of no more than 30 psia.
 19. The plant of claim13, optionally comprising an intercooler that is operationally coupledto the absorber, wherein a power plant or reforming plant isoperationally coupled to the plant, and wherein the power plant isconfigured to provide heat for a reboiler of the first regenerator, andabsorber feed gas, and wherein the power plant or reforming plant isfurther configured to optionally receive heat from the plant by at leastone of a lean solvent cooler, a semi-lean solvent cooler, a regeneratorcondenser of the plant, and the intercooler.